Seismic surveys are useful for studying subsurface formations in many contexts, including the monitoring of subsurface hydrocarbon reservoirs and the tracking of fluids, e.g. oil, gas, or water, as they flow through the subsurface strata. One type of areal monitoring that is gaining in importance is the ability to track CO2 that has been injected as part of carbon capture and sequestration (CCS) projects. Also of interest in the context of subsurface monitoring are the various fluids that are used for enhanced oil recovery (EOR), hydrocarbon saturation, fraccing operations, and the like.
Conventional seismic monitoring is typically multi-dimensional, with three dimensions relating to the spatial characteristics of the earth formation. Typically two dimensions are horizontal length dimensions, while the third relates to depth in the earth formation, which can be represented by a length coordinate, or by a time coordinate such as the two-way travel time of a seismic wave from surface to a certain depth and back. In addition, seismic data are often also acquired for at least two points in time, providing a fourth dimension. This allows changes in the seismic properties of the subsurface to be studied as a function of time. Changes in the seismic properties over time may be due to, for example, spatial and temporal variation in fluid saturation, pressure and temperature.
Seismic monitoring techniques investigate subsurface formations by generating seismic waves in the earth and measuring the time the waves need to travel between one or more seismic sources and one or more seismic receivers. The travel time of a seismic wave is dependent on the length of the path traversed, and the velocity of the wave along the path.
A typical system includes several acoustic receivers deployed across the region of interest. It is not uncommon to use hundreds or even thousands, of acoustic sensors to collect data across a desired area, as illustrated in FIG. 1. In instances where the sensors are placed in a borehole, fewer sensors are used, and the information available is correspondingly limited.
Seismic data-containing acoustic signals recorded by the seismic sensors are known as traces. The recorded traces are analyzed to derive an indication of the geology in the subsurface or other information. In order to maximize repeatability, the sensors are ideally left in place for the duration of the monitoring period.
Conventional seismic monitoring of oil or gas fields has several disadvantages. First, it is relatively expensive to acquire, deploy and maintain the large numbers of geophones or hydrophones that are needed in order to provide the desired level of resolution for the time periods that are typically involved, which may be on the order of years.
Second, the resolution of conventional systems is limited by the number and placement of the acoustic receivers. Some acoustic systems exist in which acoustic events are detected by monitoring changes in light backscattered in a fiber optic cable that is physically affected by the acoustic event. These systems are referred to as Distributed Acoustic Sensing (DAS) systems and operate using principles similar to Optical Time-Domain Reflectometry (OTDR). In OTDR, a fiber-optic cable is probed with a laser pulse from an interrogation unit. Defects in the glass backscatter the pulse (Rayleigh scattering) as it propagates along the fiber and the backscattered photons are received in a photodetector. The data is used to map the reflectivity of the fiber along its length. DAS uses a similar technique, in which external acoustic disturbances modulate the backscattered light from certain sections of the fiber. By recording these traces at high data rates (˜5 kHz), DAS transforms the fiber into a large number of distributed microphones or sensors.
These systems avoid the need for distinct acoustic sensors such as geophones or hydrophones, but depend on impurities in the optical cable to cause backscattering. Because sensitivity depends on impurities, the backscattered signal may be weak or non-existent in portions of the cable where it is desired to sense. Current DAS systems provide spatial resolution on the order of 1-10 m. This insufficient in many situations, including in-flow monitoring applications, where relevant events could be very localized (<1 m). The source of this limitation is due to the tradeoff between the length of the pulse (or spatial resolution) and measurement sensitivity. A longer laser pulse would provide a higher number of backscattered photons, but from a larger section of the fiber.
For these reasons, it is desirable to provide an areal seismic monitoring system that is inexpensive to acquire, deploy, and maintain, and which can provide high resolution with respect to the region of interest. The region of interest may include a part of the subsurface that is important to the production of hydrocarbons or because it is undergoing change in acoustic properties as compared to other regions or because it requires different seismic sampling spacing (spatial or temporal) in contrast with other regions.